Non-radioactive tracers to evaluate fracturing procedures

ABSTRACT

A method for evaluating induced fractures in a wellbore includes obtaining a first set of data in a wellbore using a downhole logging tool. A first proppant is pumped into the wellbore, after the first set of data is captured. The first proppant includes a first tracer that is not radioactive. A second proppant is also pumped into the wellbore, after the first proppant is pumped into the wellbore. The second proppant includes a second tracer that is not radioactive, and the second tracer is different than the first tracer. A second set of data is obtained in the wellbore using the downhole tool after the first and second proppants are pumped into the wellbore. The first and second sets of data are compared.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.15/831,081 filed on Dec. 4, 2017, which is herein incorporated byreference.

TECHNICAL FIELD

The present disclosure relates to tracers for evaluating fracturingprocedures. More particularly, the present disclosure relates toidentifying multiple non-radioactive tracer-tagged proppants in awellbore.

BACKGROUND

Radioactive tracers, such as Ir-192, Ir-194, Sc-46, Sb-124, Sb-122,Na-24, I-131 etc., are currently used to evaluate multiple fracturingprocedures conducted in a wellbore. More particularly, different tracersare used in multiple fracturing procedures to determine whichperforation is opened and further fractured during each fracturingprocedure.

Due to an inherited uneven mixing issue, the signals from radioactivetracers tend to fluctuate, making them difficult to detect accurately.In addition, it may be difficult to differentiate tracers inside thewellbore from tracers deep inside the subterranean formation. Moreover,due to their potentially hazardous properties, radioactive tracers havebeen strictly regulated to protect the health and safety of the publicand the environment. As a result, the evaluation of fractures in thesubterranean formation may not be reliable, especially for horizontalwellbores, where radioactive tracers may settle along the bottom of thewellbore in the horizontal portion.

More recently, non-radioactive tracers have been implemented. Thenon-radioactive tracers are used to tag a proppant that is pumped intothe wellbore during a fracturing procedure. The tagged proppant may beevaluated two different ways. The first method measures detector countrates of the tagged proppant using a compensated neutron (CNT) loggingtool, or measures count rates and the decay of pulsed neutrons using apulsed neutron capture (PNC) logging tool, to locate tagged proppant inthe wellbore in induced fractures, gravel packs, frac-packs, and cement.The second method measures capture gamma ray spectroscopy using a PNClogging tool and spectrally resolves the capture gamma rays emanatingfrom the tagged proppant from the capture gamma rays coming from otherdownhole elements. These techniques have been disclosed in U.S. Pat.Nos. 8,100,177, 8,648,309, 8,805,615, and 9,038,715. Although a singlenon-radioactive tracer-tagged proppant has been used for evaluating thefracture height or gravel pack quality, there is a need for a method todetect and measure multiple (e.g., different) non-radioactive tracers toevaluate multiple fracture procedures for the same stage or differentstages of a wellbore, as well as how the logging procedures areperformed and how the logs are evaluated.

BRIEF SUMMARY

A method for evaluating induced fractures in a wellbore is disclosed.The method includes obtaining a first set of data in a wellbore using adownhole logging tool. A first proppant is pumped into the wellbore,after the first set of data is captured. The first proppant includes afirst tracer that is not radioactive. A second proppant is also pumpedinto the wellbore, after the first proppant is pumped into the wellbore.The second proppant includes a second tracer that is not radioactive,and the second tracer is different than the first tracer. A second setof data is obtained in the wellbore using the downhole tool after thefirst and second proppants are pumped into the wellbore. The first andsecond sets of data are compared.

In another embodiment, the method includes pumping a first proppant intothe wellbore. The first proppant includes a first tracer that is notradioactive. A second proppant is also pumped into the wellbore,simultaneously with or after the first proppant is pumped into thewellbore. The second proppant includes a second tracer that is notradioactive, and the second tracer is different than the first tracer. Aset of data is obtained in the wellbore using a downhole logging toolafter the first and second proppants are pumped into the wellbore. Theset of data is analyzed to determine locations of the first and secondproppants in formation fractures.

In another embodiment, the method includes obtaining a first set of datain a wellbore using a downhole tool. A frac fluid and a proppant arepumped into the wellbore simultaneously, after the first set of data iscaptured. The frac fluid includes a first tracer that is notradioactive, and the proppant includes a second tracer that is notradioactive. A second set of data is obtained in the wellbore using thedownhole tool after the frac fluid and the proppant are pumped into thewellbore. The first and second sets of data are compared to determinelocations of the frac fluid the said proppant.

A method for evaluating gravel packs or frac packs in a wellbore is alsodisclosed. The method includes pumping a first proppant into thewellbore. The first proppant includes a first tracer that is notradioactive. A second proppant is also pumped into the wellbore,simultaneously with or after the first proppant is pumped into thewellbore. The second proppant includes a second tracer that is notradioactive, and the second tracer is different than the first tracer. Afirst set of data is obtained in the wellbore using a downhole loggingtool after the first and second proppants are pumped into the wellbore.The first set of data is analyzed to determine locations of the firstand second proppants in a gravel pack region in the wellbore, in inducedformation fractures, or both.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention may best be understood by referring to thefollowing description and accompanying drawings that are used toillustrate embodiments of the invention. In the drawings:

FIG. 1 is a schematic view of a two-stage fracturing treatment in awellbore, according to an embodiment.

FIG. 2 is a schematic view of a downhole pulsed neutron logging tool inthe wellbore, according to an embodiment.

FIG. 3 is a flowchart of a method for evaluating multiple fractures inthe wellbore using data obtained by the downhole tool, according to anembodiment.

FIG. 4 is a graph (e.g., a log) showing data obtained by the downholepulsed neutron tool in the wellbore before and after a stage isfractured with a gadolinium-tagged proppant and a boron-tagged proppant,according to an embodiment.

FIG. 5 is graph (e.g., a log) showing data obtained by the downholepulsed neutron tool in the wellbore before and after a stage isfractured, with a gadolinium-tagged proppant, a boron-tagged proppant,and a samarium-tagged proppant, according to an embodiment.

FIG. 6 is a graph showing modeled pulsed neutron logging tool detectorcapture gamma ray count rate changes in an early time window (e.g., 50μs to 150 μs) relative to the timing of the neutron burst (e.g., 0 μs to30 μs) with gadolinium and boron used as non-radioactive proppant tagsin a fractured formation, according to an embodiment.

FIG. 7 is a graph showing modeled pulsed neutron logging tool detectorcapture gamma ray count rate changes in a late time window (e.g., 200 μsto 1000 μs) relative to the neutron bursts (e.g., 0 μs to 30 μs) withgadolinium and boron used as non-radioactive proppant tags in afractured formation, according to an embodiment.

FIG. 8 is a table showing modeled changes on pulsed neutron loggingborehole sigma, formation sigma, detector count rates in different timewindows, and a ratio of detector count rate changes in two time windows(e.g. 50-150 μs and 200-1000 μs) for a Gd-tagged proppant, a B-taggedproppant, and a Sm-tagged proppant in a fractured formation, accordingto an embodiment.

FIG. 9 is a graph showing the capture gamma spectral differences betweena Gd-tagged proppant and a Sm-tagged proppant in a downhole proppedfracture, according to an embodiment.

DETAILED DESCRIPTION

The present disclosure is directed to systems and methods for detectingand identifying multiple (e.g., different) non-radioactive tracer-taggedproppants and/or frac fluids (and in some embodiments non-radioactivetagged proppants/fluids in combination with radioactively taggedmaterials) in induced formation fractures in a wellbore using a pulsedneutron capture (PNC) tool. FIG. 1 is a schematic view of a two-stagefracturing treatment in a wellbore 102, according to an embodiment. Thewellbore 102 may extend into a subterranean formation having one or morelayers. For example, the wellbore 102 may include a substantiallyvertical portion that extends downward through a first formation layer104, a second formation layer 105, a third formation layer 106, and areservoir layer 107. The wellbore 102 may also include a substantiallyhorizontal portion (e.g., in the reservoir layer 107).

The wellbore 102 may be cased or uncased and perforated and/or fracturedin one or more stages. As shown, the horizontal portion of the wellbore102 may be perforated and/or fractured in two stages: a first stage 110and a second stage 120. The first stage 110 may be positioned below(e.g., farther from the origination point of the wellbore 102 than) thesecond stage 120. The first stage 110 may be perforated and/or fracturedbefore the second stage 120.

The first stage 110 may include one or more sets of perforations (twoare shown: 112, 114). The first set of perforations 112 may be axiallyoffset from the second set of perforations 114 with respect to the axisalong the wellbore 102. For example, the first set of perforations 112may be positioned below (e.g., farther from the origination point of thewellbore 102 than) the second set of perforations 114. The first set ofperforations 112 may be generated before or at the same time as thesecond set of perforations 114. After the first and second sets ofperforations 112, 114 are formed, a first fracturing procedure may beinitiated. The first fracturing procedure may include pumping a firstnon-radioactive-tagged proppant into the wellbore 102. As used herein,the term “non-radioactive-tagged proppant” refers to a proppant that istagged by a tracer material that is not radioactive and has a highthermal neutron capture cross-section. The tracer in the firstnon-radioactive-tagged proppant may be or include, for example,gadolinium (Gd). For example, the tracer may be or include Gd₂O₃. Afterthe first fracturing procedure is completed, a second fracturingprocedure may be initiated. The second fracturing procedure may includepumping a second non-radioactive-tagged proppant into the wellbore 102.In one embodiment, the first fracturing procedure may contain taggedproppant particles of one size (mesh), and the following treatment maycontain tagged proppant particles of a different size (mesh). The tracerin the second non-radioactive-tagged proppant may be different from thefirst non-radioactive-tagged proppant. The tracer in the secondnon-radioactive-tagged proppant may be or include, for example, boron(B). For example, the tracer may be or include B₄C. The twonon-radioactively tagged proppants may also be employed in a single fracprocedure where an initial portion of the treatment contained one tagmaterial and a second portion contains the second tag material.

As described in more detail below, if the first non-radioactive-taggedproppant (e.g., the Gd-tagged proppant) is found in the fracture inducedby the first set of perforations 112, and the secondnon-radioactive-tagged proppant (e.g., the B-tagged proppant) is foundin the fracture induced by the second set of perforations 114, it may bedetermined that the first set of perforations 112 was opened/fracturedby the first non-radioactive-tagged proppant before the second set ofperforations 114 was opened/fractured by the secondnon-radioactive-tagged proppant. However, if the firstnon-radioactive-tagged proppant (e.g., the Gd-tagged proppant) is foundin the fracture induced by the second set of perforations 114, and thesecond non-radioactive-tagged proppant (e.g., the B-tagged proppant) isfound in the fracture induced by the first set of perforations 112, thenit may be determined that the second set of perforations 114 wasopened/fractured by the first non-radioactive-tagged proppant before thefirst set of perforations 112 was opened/fractured by the secondnon-radioactive-tagged proppant.

The second stage 120 may also include one or more sets of perforations(three are shown: 122, 124, 126). For example, the third set ofperforations 122 may be positioned below (e.g., farther from theorigination point of the wellbore 102 than) the fourth set ofperforations 124, and the fourth set of perforations 124 may bepositioned below the fifth set of perforations 126. After the third,fourth, and fifth sets of perforations 122, 124, 126 are formed, a thirdfracturing procedure may be initiated. The third fracturing proceduremay be the first fracturing procedure in the second stage 120. The thirdfracturing procedure may include pumping a third non-radioactive-taggedproppant into the wellbore 102. The tracer in the thirdnon-radioactive-tagged proppant may be the same as or different from thetracers in the non-radioactive-tagged proppants used in the first stage110. For example, the tracer in the third non-radioactive-taggedproppant may be or include, for example, gadolinium (Gd). For example,the tracer may be or include Gd₂O₃.

After the third fracturing procedure is completed, a fourth fracturingprocedure may be initiated. The fourth fracturing procedure may includepumping a fourth non-radioactive-tagged proppant into the wellbore 102.The tracer in the fourth non-radioactive-tagged proppant may be the sameas or different from the tracers in the non-radioactive-tagged proppantsused in the first stage 110. The tracer in the fourthnon-radioactive-tagged proppant may be different from the tracer in thethird non-radioactive-tagged proppant. For example, the tracer in thefourth non-radioactive-tagged proppant may be or include, for example,boron (B). For example, the tracer may be or include B₄C.

After the fourth fracturing procedure is completed, a fifth fracturingprocedure may be initiated. The fifth fracturing procedure may includepumping a fifth non-radioactive-tagged proppant into the wellbore 102.The tracer in the fifth non-radioactive-tagged proppant may be the sameas or different from the tracers in the non-radioactive-tagged proppantsused in the first stage 110. The tracer in the fifthnon-radioactive-tagged proppant may be different from the tracers in thethird and/or fourth non-radioactive-tagged proppants. For example, thetracer in the fifth non-radioactive-tagged proppant may be or include,for example, samarium (Sm). For example, the tracer may be or includeSm₂O₃. Other example non-radioactive tracers may be or include tracerswith a high thermal neutron capture cross-section (e.g., cadmium,iridium, or dysprosium).

In the example of the second stage 120, the fracturing procedures maynot occur in/through the desired perforations. For example, in theexample of the second stage 120, if the third non-radioactive-taggedproppant (e.g., the Gd-tagged proppant) is found in the fracture inducedby the fifth set of perforations 126, the fourth non-radioactive-taggedproppant (e.g., the B-tagged proppant) is found in the fracture inducedby the fourth set of perforations 124, and the fifthnon-radioactive-tagged proppant (e.g., the Sm-tagged proppant) is foundin the fracture induced by the third set of perforations 122, it may bedetermined that the fifth set of perforations was opened/fractured bythe third non-radioactive-tagged proppant, and then the fourth set ofperforations 124 was opened/fractured by the fourthnon-radioactive-tagged proppant, and then the third set of perforations122 was opened/fractured by the fifth non-radioactive-tagged proppant.

The same principles described above for a two-stage fracturing operationmay be applied in a single-stage fracturing operation, for example, whena first portion of the proppant being pumped (i.e., a lead-in portion)contains the first non-radioactive tracer, and a second, subsequentportion of the proppant being pumped (i.e., a tail-in portion) containsthe second non-radioactive tracer. This may provide information that maybe used to determine which fractured intervals were more easilyfractured and received the first non-radioactive-tagged proppant, andwhich intervals received the second non-radioactive-tagged proppant.Also, if one of the tracer materials is detected in more than one (e.g.,all) of the propped fractures, this may provide information to determinewhether or not, in future wells, it may be possible to tag only aportion (e.g., the tail-in portion) of the pumped proppant.

A fracturing design/procedure may include fracturing an entire targetzone in a vertical portion of the wellbore from bottom to top, or anentire target zone in a horizontal portion of the wellbore from toe toheel, and there may be no zone left unfractured to improve the ultimateoil or gas recovery. If the entire zone is not fractured as planned(e.g., from bottom to top or from toe to heel or some zone is leftunfractured), it may be useful for an operator to know the sequence offractures or to modify the fracturing design and procedure.Alternatively, in addition to using plugs, the operator may also sealthe opened perforations/fractures to fracture the un-openedperforations/unfractured zones, thereby potentially making thefracturing operation costly and risky.

FIG. 2 is a schematic view of a downhole tool 200 in the wellbore 102,according to an embodiment. In at least one embodiment, the downholetool 200 may include a natural gamma ray detector and/or a pulsedneutron logging tool containing a pulsed neutron source and one or moregamma ray detectors. The downhole tool 200 may be run into the wellbore102 and obtain measurements before the fracturing procedures and/orafter the fracturing procedures. In one example, the downhole tool 200may be run into the wellbore 102 and obtain measurements before thefracture procedures in the first stage 110 and the second stage 120, andthen again after the fracture procedures in the first stage 110 and thesecond stage 120. In another example, the downhole tool 200 may be runinto the wellbore 102 and obtain measurements before the fractureprocedures in the first stage 110, after the fracture procedures in thefirst stage 110 and before the fracture procedure in the second stage120, and after the fracture procedures in the second stage 120. Asshown, the downhole tool 200 may be raised and lowered in the wellbore102 via a wireline 202. In other embodiments, the downhole tool 200 mayinstead be raised and lowered by a drill string. The data obtained bythe downhole tool 200 may be transmitted to, stored in, and/or analyzedby a computing system 204. The computing system 204 may be positionedin, or otherwise part of, a mobile unit, such as a truck.

FIG. 3 is a flowchart of a method 300 for evaluating multiple fracturesin the wellbore 102, according to an embodiment. The method 300 mayinclude obtaining (e.g., logging) a first set of data in the wellbore102 using the downhole tool 200 (e.g., before the first stage 110 isfractured), as at 302. The first set of data may be referred to as abefore-fracture log. The first set of data may be or include naturalgamma ray, borehole sigma, formation sigma, detector count rates indifferent time windows, ratios of detector count rates in different timewindows, a taggant/tracer element yield (e.g., Gd yield), temperature,wellbore fluid density, wellbore salinity, or a combination thereof. Thedata collection may begin below the first set of perforations 112 andcontinue to above (e.g., 200-300 feet above) the fifth set ofperforations 126.

The method 300 may also include fracturing the first stage 110 of thewellbore 102, as at 304. In at least one embodiment, fracturing thefirst stage 110 of the wellbore 102 may include pumping the firstnon-radioactive-tagged proppant (e.g., the Gd-tagged proppant) intowellbore 102. For example, the first non-radioactive-tagged proppant(e.g., the Gd-tagged proppant) may be intended to flow into the fractureinduced by the first set of perforations 112. Fracturing the first stage110 of the wellbore 102 may also include pumping the secondnon-radioactive-tagged proppant (e.g., the B-tagged proppant) intowellbore 102. For example, the second non-radioactive-tagged proppant(e.g., the B-tagged proppant) may be intended to flow into the fractureinduced by the second set of perforations 114.

The method 300 may also include obtaining (e.g., logging) a second setof data in the wellbore 102 using the downhole tool 200 (e.g., after thefirst stage 110 is fractured), as at 306. The second set of data may bereferred to as the first after-fracture log because it represents datacaptured after the first stage 110 is fractured. The second set of datamay include the same type(s) of data as the first set of data.

The method 300 may also include normalizing the first and/or secondset(s) of data, as at 308. Normalizing the first and/or second set(s) ofdata may account for possible changes inside the wellbore 102 or casingso that the first set of data (i.e., the before-fracture log) overlayswith the second set of data (i.e., the after-fracture log) in the depthinterval where there is/are no fracture(s) (e.g., in a depth intervalabove the first stage 110 and/or above the second stage 120).

The method 300 may also include comparing the first set of data (i.e.,the before-fracture log) with the second set of data (i.e., the firstafter-fracture log), as at 310. The comparison may occur after thenormalizing. The comparison may include, but is not limited to,comparing the natural gamma ray, borehole sigma, formation sigma,taggant/tracer element yield (e.g., Gd yield), detector count rates indifferent time windows, ratios of detector count rates in different timewindows, or a combination thereof.

In one example, if the comparison shows that the taggant/tracer elementyield (e.g., Gd yield) increases proximate to a particular set ofperforations (e.g., the first set of perforations 112), it may bedetermined that the Gd-tagged proppant was successfully placed in thefirst set of perforations 112. In another example, if the comparisonshows that the detector count rates increase in an early time window(e.g., 35 μs to 200 μs or 50 μs to 150 μs) after the neutron bursts(e.g., 0 μs to 30 μs) proximate to a particular set of perforations(e.g., the first set of perforations 112), it may be determined that theGd-tagged proppant was successfully placed in the first set ofperforations 112. In yet another example, if the comparison shows thatthe detector count rates decrease at a particular rate in a late timewindow (e.g., 150 μs to 500 μs or 200 μs to 1000 μs) proximate to aparticular set of perforations (e.g., the first set of perforations112), it may be determined that the Gd-tagged proppant was successfullyplaced in the first set of perforations 112.

In another example, if the comparison shows that the detector countrates decrease in an early time window (e.g., 35 μs to 200 μs or 50 μsto 150 μs) relative to the neutron bursts (e.g., 0 μs to 30 μs)proximate to a particular set of perforations (e.g., the second set ofperforations 114), it may be determined that the B-tagged proppant wassuccessfully placed in the second set of perforations 114. In yetanother example, if the comparison shows that the detector count ratesdecrease at a particular rate in a late time window (e.g., 150 μs to 500μs or 200 μs to 1000 μs) proximate to a particular set of perforations(e.g., the second set of perforations 114), it may be determined thatthe B-tagged proppant was successfully placed in the second set ofperforations 114. The count rates are discussed in greater detail belowwith reference to FIGS. 4-7.

The method 300 may also optionally include fracturing the second stage120 of the wellbore 102, as at 312. The wellbore 102 may be fracturedafter the perforations 122, 124, 126 are formed. In at least oneembodiment, fracturing the second stage 110 of the wellbore 102 mayinclude pumping the third non-radioactive-tagged proppant (e.g., theGd-tagged proppant) into wellbore 102. For example, the thirdnon-radioactive-tagged proppant (e.g., the Gd-tagged proppant) may beintended to flow into the fracture induced by the third set ofperforations 122. Fracturing the second stage 120 of the wellbore 102may also include pumping the fourth non-radioactive-tagged proppant(e.g., the B-tagged proppant) into wellbore 102. For example, the fourthnon-radioactive-tagged proppant (e.g., the B-tagged proppant) may beintended to flow into the fracture induced by the fourth set ofperforations 124. Fracturing the second stage 120 of the wellbore 102may also include pumping the fifth non-radioactive-tagged proppant(e.g., the Sm-tagged proppant) into wellbore 102. For example, the fifthnon-radioactive-tagged proppant (e.g., the Sm-tagged proppant) may beintended to flow into the fracture induced by the fifth set ofperforations 126. The use of three non-radioactive tagged proppants mayalso be used in a single stage fracturing operation, or a fracturingoperation having more than two stages.

The method 300 may also include obtaining (e.g., logging) a third set ofdata in the wellbore 102 using the downhole tool 200 (e.g., after thesecond stage 120 is fractured), as at 314. The third set of data may bereferred to as the second after-fracture log because it represents datacaptured after the second stage 120 is fractured. The third set of datamay include the same type(s) of data as the first and/or second sets ofdata.

The method 300 may also include normalizing the first and third sets ofdata or the second and third sets of data, as at 316. Normalizing thedata may account for possible changes inside the wellbore 102 or casing.

The method 300 may also include comparing the second set of data (i.e.,the first after-fracture log) with the third set of data (i.e., thesecond after-fracture log), as at 318. Alternatively, 318 may includecomparing the first set of data (i.e., the before-fracture log) with thethird set of data (i.e., the second after-fracture log). The comparisonmay include, but is not limited to, comparing the natural gamma ray,borehole sigma, formation sigma, taggant/tracer element yield (e.g., Gdor Sm yield), detector count rates in different time windows, a ratio ofdetector count rates in different time windows, or a combinationthereof.

In one example, if the comparison shows that the taggant/tracer elementyield (e.g., Gd yield) increases proximate to a particular set ofperforations (e.g., the fifth set of perforations 126), it may bedetermined that the Gd-tagged proppant was successfully placed in thefifth set of perforations 126. In another example, if the comparisonshows that the taggant/tracer element yield (e.g., Sm yield) increasesproximate to a particular set of perforations (e.g., the third set ofperforations 122), it may be determined that the Sm-tagged proppant wassuccessfully placed in the third set of perforations 122. As will bedescribed below with reference to FIG. 9, the Gd-tagged proppant and theSm-tagged proppant may be distinguished from one another using spectraldata processing methods in determining the elemental yields of Gd andSm.

In another example where gadolinium and boron are the two taggants, ifthe comparison shows that the detector count rates increase in an earlytime window (e.g., 35 μs to 200 μs or 50 μs to 150 μs) proximate to aparticular set of perforations (e.g., the fifth set of perforations126), it may be determined that the Gd-tagged proppant was successfullyplaced in the fifth set of perforations 126. In yet another example, ifthe comparison shows that the detector count rates decrease at aparticular rate in a late time window (e.g., 150 μs to 500 μs or 200 μsto 1000 μs) proximate to a particular set of perforations (e.g., thefifth set of perforations 126), it may be determined that the Gd-taggedproppant was successfully placed in the fifth set of perforations 126.

In the example with the Gd and B taggants, if the comparison shows thatthe detector count rates decrease in an early time window (e.g., 35 μsto 200 μs or 50 μs to 150 μs) proximate to a particular set ofperforations (e.g., the third set of perforations 122), it may bedetermined that the B-tagged proppant was successfully placed in thethird set of perforations 122. In yet another example, if the comparisonshows that the detector count rates decrease more in a late time window(e.g., 150 μs to 500 μs or 200 μs to 1000 μs) proximate to a particularset of perforations (e.g., the third set of perforations 122), it may bedetermined that the B-tagged proppant was successfully placed in thethird set of perforations 122. Also, because a ratio of the count ratechange in the early time window relative to the later time windowbetween the before-frac and after-frac measurements for agadolinium-tagged proppant is different from the corresponding countchange for a boron-tagged proppant, an analysis of the ratio measurementin the fractured zones 122, 126 would indicate which taggant was present(e.g. the ratio is negative for Gd-tagged proppant but positive forB-tagged proppant in a fractured zone).

The method 300 may also include calibrating a fracture model in responseto the comparisons, as at 320. The fracture model may be calibrated toreduce the uncertainties in fracture procedure designs. This may lead tomore efficient fracturing procedures and improve the ultimate oil or gasrecovery. For example, the lead-in portion of the proppant may notinclude a tracer, and only the tail-in portion of the proppant mayinclude the tracer. In another embodiment, the particles size(s) in theproppant(s) may be varied in response to the comparisons for futurefracture operations.

FIG. 4 is a graph 400 showing the first and second sets of data obtainedby the downhole tool 200 in the wellbore 102 (i.e., before and after thefirst stage 110 is fractured), according to an embodiment. The graph 400has columns showing the measured depth 410, the natural gamma ray 420,the perforation intervals 430, the ratio of count rates from near andfar detector 440, the borehole sigma 450, the formation sigma 460, thecount rate in an early time window (e.g., 50 μs to 150 μs) 470, thecount rate in a late time window (e.g., 200 μs to 1000 μs) 475, and thetaggant/tracer element (e.g., Gd) yield 480.

As shown, the after-fracture borehole sigma may be larger proximate toboth sets of perforations 112, 114 after the first stage 110 isfractured, and the after-fracture formation sigma may be largerproximate to both sets of perforations 112, 114 after the first stage110 is fractured. The count rates in the early time window may increaseproximate to the first set of perforations 112 and decrease proximate tothe second set of perforations 114 after the first stage 110 isfractured. The count rates in the late time window may decreaseproximate to both sets of perforations 112, 114 in differing relativeamounts after the first stage 110 is fractured. The taggant/tracerelement (e.g., Gd) yield may be larger proximate to the first set ofperforations 112 after the first stage 110 is fractured, and there maybe substantially no change in the taggant/tracer element (e.g., Gd)yield proximate to the second set of perforations 114 after the firststage 110 is fractured. From any portion (or all) of this data, it maybe determined that the Gd-tagged proppant flowed into the fractureinduced by the first set of perforations 112, and the B-tagged proppantflowed into the fracture induced by the second set of perforations 114.

FIG. 5 is a graph 500 showing the second and third sets of data capturedby the downhole tool 200 in the wellbore 102 (i.e., before and after thesecond stage 120 is fractured), according to an embodiment. FIG. 5 mayalso describe multiple perforations and multiple tracers in a singlestage fracture procedure. As shown, the borehole sigma may be largerproximate to all three sets of perforations 122, 124, 126 after thesecond stage 120 is fractured, and the formation sigma may be largerproximate to all three sets of perforations 122, 124, 126 after thesecond stage 120 is fractured. In the example of FIG. 5, the downholetool 200 is able to measure the Gd yield 480 and the Sm yield 490. Asshown, the Gd yield 480 may increase proximate to the fifth set ofperforations 126, and the Sm yield 490 may increase proximate to thethird set of perforations 122. The count rates in the early time windowmay increase proximate to the third and fifth sets of perforations 122,126 and decrease proximate to the fourth set of perforations 124 afterthe second stage 120 is fractured, and the count rates in the late timewindow may decrease proximate to all three sets of perforations 122,124, 126 after the second stage 120 is fractured. The taggant/tracerelement (e.g., Gd) yield may be larger proximate to the fifth set ofperforations 126 after the second stage 120 is fractured, and there maybe no change in the taggant/tracer element (e.g., Gd) yield proximate tothe third or fourth set of perforations 122 and 124 after the secondstage 120 is fractured. The taggant/tracer element (e.g., Sm) yield maybe larger proximate to the third set of perforations 122 after thesecond stage 120 is fractured, and there may be no change in thetaggant/tracer element (e.g., Sm) yield proximate to the fourth or fifthsets of perforations 124 and 126 after the second stage 120 isfractured. From any portion (or all) of this data, it may be determinedthat the B-tagged proppant flowed into the fracture induced by thefourth set of perforations 124, because the sigma-formation andsigma-borehole logs increase after the fracture procedure indicatingthat a non-radioactive tag is present, but neither Gd nor Sm is seen onthe yield logs, which indicates that neither Gd nor Sm is present inperforations 124. The presence of boron is also indicated in the fourthset of perforations 124 because there is a decrease in the early timewindow count rate in perforations 124. An increase in the early timewindow count rate may be observed if Gd or Sm were the taggant presentin perforations 124.

Although not shown, a similar graph may be generated with the first andthird sets of data. From this data analysis, it may be determined thatthe Gd-tagged proppant flowed into the fracture induced by the fifth setof perforations 126, the B-tagged proppant flowed into the fractureinduced by the fourth set of perforations 124, and the Sm-taggedproppant flowed into the fracture induced by the third set ofperforations 122.

FIG. 6 is a graph 600 showing the detector count rates in an early timewindow (e.g., 50 μs to 150 μs) after the end of each neutron burst (e.g.0 to 30 μs), according to an embodiment. More particularly, FIG. 6 showsthe detector count rates for the Gd-tagged proppant and the B-taggedproppant in the early time window as a function of different taggantconcentrations (weight percentages) in the proppant particles. As may beseen, the count rate for the Gd-tagged proppant increases, whereas thecount rate for the B-tagged proppant decreases, regardless of theproppant concentrations. In one example, the proppant concentrations maybe about 0.4% for the Gd-tagged proppant and about 1.0% for the B-taggedproppant.

FIG. 7 is a graph 700 showing the detector count rates in a late timewindow (e.g., 200 μs to 1000 μs) after the end of each neutron burst,according to an embodiment. More particularly, FIG. 7 shows the detectorcount rates for the Gd-tagged proppant and the B-tagged proppant in thelate time window as a function of taggant concentration in the proppantparticles. As may be seen, the count rates for both the Gd-taggedproppant and the B-tagged proppant decrease, regardless of the proppantconcentrations. However, the count rate of the B-tagged proppant maydecrease different (e.g., larger) amounts/percentages than the Gd-taggedproppant. Again, the proppant concentrations may be about 0.4% for theGd-tagged proppant and about 1.0% for the B-tagged proppant.

FIG. 8 is a table 800 showing modeled changes on pulsed neutron loggingborehole sigma, formation sigma, detector count rates in different timewindows, and a ratio of detector count rate changes in two time windows(e.g. 50-150 μs to 200-1000 μs) from a near-spaced detector for aGd-tagged proppant, a B-tagged proppant, and a Sm-tagged proppant, fornominal taggant concentrations used in typical field applications. Theseconcentrations result in similar increases in a propped fracture of theformation capture cross-section am (all three increase approximately 10%in the table). On the other hand, the detector count rates in the earlytime window increase for both Gd and Sm taggants, whereas the count ratedecreases for a boron taggant. This is due in part to the fact that bothGd and Sm emit significant high energy capture gamma radiation followingthermal neutron capture, whereas boron does not. In the later timewindows (e.g., 200 μs to 1000 μs or 400 μs to 1000 μs) relative to thetime of the neutron bursts, the detector count rates decrease for allthree taggant materials, and the relative decrease is larger for boron.Also shown in FIG. 8 are the ratio of the detector count rate changes inthe early time window relative to that in a later time window for allthree taggant materials. It can be seen that the ratios are similar whenGd and Sm taggants are present (e.g., negative); however, the ratio issignificantly different when boron is the taggant (e.g., positive).Thus, to distinguish the signal from the B-tagged proppant from signalsfrom either Gd or Sm-tagged proppants, the operator may use thedifferent boron tag signature in the early time window count rate or themore pronounced ratio of count rate changes in different time windowswhen tagged proppant is present. It can also be seen from the similarityof the data in the table for Gd and Sm that an additional discriminatoris required to distinguish the presence of a Gd taggant from a Smtaggant.

FIG. 9 is a graph 900 showing the modeled pulsed neutron capture gammaray energy spectra illustrating the differences between Gd-taggedproppant and Sm-tagged proppant in a downhole induced fracture. Asshown, the Gd-tagged proppant and the Sm-tagged proppant producesomewhat distinctive capture gamma ray spectra. Therefore capture gammaray spectroscopy processing techniques may be used to determine theyields from each of the two different taggants (Gd and Sm), and thedifferences, and hence, the yields of elements may indicate whichperforations contained which of these tagged proppants.

In a fracturing operation utilizing one or both of these two taggants(e.g., Gd and Sm), if neither of these spectrally-distinctnon-radioactive tracers are otherwise present in the downhole formationsand wellbore region, then it may also be possible to eliminate or omitthe pre-fracture data set and instead utilize the two yields (or yieldsabove statistical background levels) determined from the after-fracturedata set, perhaps in combination with other PNC log parameters, in theprocess to determine the locations within the fractured zones where eachof the tagged proppant materials is present.

The multiple non-radioactive tracers may also be used to evaluatefrac-packing. Frac-packing is a technique that merges two completionprocesses: hydraulic fracturing and gravel packing. After frac-packing,the quality of the gravel pack may be evaluated to ensure thatsuccessful sand control has been obtained. The fracture height in theformation may also be determined behind the gravel pack. Multipletracers may be used to evaluate frac-packing procedures for a wellborewith one or more sets of perforations.

In at least one embodiment, two sets of proppant particles havingdifferent sizes may be used in a fracturing operation or a frac-packingoperation. For example, the lead-in portion of the proppant may havesmaller particles, and the tail-in portion of the proppant may havelarger particles. The smaller particles may be tagged with onenon-radioactive tracer, and the larger particles may be tagged with adifferent non-radioactive tracer. Analysis of fracturing data may beperformed to determine fractures where the smaller versus largerproppant particles are located, and can also be useful in designingfuture fracturing procedures. This may also be useful information infrac-pack evaluation or for developing future frac-pack procedures. Forexample, an operator may determine whether the larger or smallerproppant particles are preferentially located in the gravel packedregion in the borehole or the fractured zone(s) out in the formation.

In at least one embodiment, it may be useful to tag the proppant pumpedin a fracturing operation with one or more non-radioactive tracers, andthe frac fluid pumped downhole containing the proppant with a differentnon-radioactive tracer, also having a high thermal neutron capturecross-section. The frac fluid tracer/taggant may be dissolved orotherwise contained in the frac fluid being pumped (e.g., water-solublenon-radioactive boron tracers may include boric acid or borax). Thetagged proppant and the tagged frac fluid may be pumped into thewellbore simultaneously or at different times. If the water-solubletracer does contain boron, the boron tracer signals in the frac fluidmay also be augmented by any boron otherwise present in the frac fluid(e.g., some cross-linked frac fluids contain boron compounds). Theability to independently locate the tracers in the frac fluid versus thetracers in the proppant may allow determination of any zones which werefractured, but not effectively propped. This data may also provideuseful information in the overall fracture evaluation and designprocesses.

In at least one embodiment, one or more non-radioactive tracers may beused in combination with a radioactive (R/A) tracer/taggant. Forexample, the frac fluid may be tagged with a radioactive tracer, and theproppant may be tagged with one or more non-radioactive tracers. Thismay reduce the number of non-radioactive tracers used, and also make anyspectral analysis of the radioactive tag signals and/or thenon-radioactive tag signals easier and more accurate, because the R/Ameasurement may be made by a different detector in the logging tool thanthe detector(s) used to process the data from the non-radioactive tag.Conventionally, if an operator wanted to distinguish how much of two ormore R/A taggants are in the borehole region versus the formation, thespectral data processing is very complex and can be highly inaccurate.That is not true if one is using only one R/A tag, where gamma rayspectroscopy can more effectively be used to distinguish that taggant inthe borehole region from taggant in the formation fractures. Hence,combining a R/A taggant with a non-radioactive taggant may permitindependent processing and methods in obtaining the two taggantdeterminations and may permit more accurate analysis from the R/A data,since the second R/A tag can be eliminated, and thus would not bepresent to interfere with or otherwise introduce inaccuracy into theanswers relating the first R/A taggant.

Isolating two R/A taggants involves using capture gamma rayspectroscopy, and conventionally, a specialized tool is used to make themeasurements. Using one R/A taggant with one non-radioactive taggantdoes not use capture gamma ray spectroscopy, whether using a PNC tool todetect the non-radioactive taggant or a compensated neutron tool. Any ofthe non-radioactive taggants may be used (e.g., Gd, Sm, or B). Inaddition, an operator does not require the use of different tools todetect an R/A taggant and a non-radioactive taggant. Both can bedetected using the same pulsed neutron tool used to detect thenon-radioactive taggant. Even a compensated neutron tool may be used toisolate signals from an R/A tag and a single non-radioactive tag. Thenatural gamma ray detector in the pulsed neutron or compensated neutrontool may be used to detect the R/A taggant in the fractures by comparingthe before-frac natural gamma ray log with the after-frac natural gammaray log. The gamma ray log increase on the after-frac log may be due tothe gamma rays from the R/A taggant. This natural gamma detector is notused in determining/analyzing the non-radioactively tagged proppant datain determining the non-radioactive proppant signal(s).

A pulsed neutron tool, if so equipped, may also make use of the abilityto utilize capture gamma spectroscopy (when available) to improve thenon-radioactive taggant data analysis by computing the taggant yield(s).In that case, it would be possible to distinguish two or threenon-radioactive taggants (e.g., Gd, Sm, and/or B), as illustrated inFIGS. 4 and 5, if it were desired to use more than two taggants (e.g.,one R/A tag and two or three non-radioactive tags). A positive costsaving in using a R/A taggant with one or more non-radioactive taggantsis that an additional logging tool would not be required to detect theR/A taggant. All the taggants may be located using the same pulsedneutron tool (or compensated neutron tool for one R/A tag and onenon-radioactive tag) currently in use for non-radioactive taggant dataprocessing. Also, during the logging operation, no additional loggingpasses up the borehole would be required to detect the presence of theR/A tag, since all the tag signals are simultaneously obtained.

In another embodiment, a method for evaluating induced fractures in awellbore using radioactive and non-radioactive tags may include pumpinga proppant into the wellbore, wherein the proppant includes a firsttracer that is not radioactive. A second tracer may also be pumped intothe wellbore before, simultaneously with, and/or after the proppant ispumped into the wellbore. The second tracer is radioactive. A first setof data may be obtained in the wellbore using a downhole logging toolafter the first and second tracers are pumped into the wellbore. Thefirst set of data may be analyzed to determine locations of the firstand second tracers in formation fractures. The method may also includecapturing a second set of data with the downhole logging tool prior topumping the proppant and the second tracer, and comparing the first andsecond sets of data to determine the locations of the first and secondtracers in the formation fractures.

It is understood that modifications to the invention may be made asmight occur to one skilled in the field of the invention within thescope of the appended claims. All embodiments contemplated hereunderwhich achieve the objects of the invention have not been shown incomplete detail. Other embodiments may be developed without departingfrom the spirit of the invention or from the scope of the appendedclaims. Although the present invention has been described with respectto specific details, it is not intended that such details should beregarded as limitations on the scope of the invention, except to theextent that they are included in the accompanying claims.

What is claimed is:
 1. A method for evaluating induced fractures in awellbore, comprising: pumping a first proppant into the wellbore,wherein the first proppant comprises a first tracer comprising anelement selected from the group consisting of gadolinium, boron, andsamarium; pumping a second proppant into the wellbore, simultaneous withor after the first proppant is pumped into the wellbore, wherein thesecond proppant comprises a second tracer comprising a different elementselected from the group consisting of gadolinium, boron, and samarium,and wherein the second tracer is different than the first tracer;obtaining a set of data in the wellbore using a pulsed neutron loggingtool after the first and second proppants are pumped into the wellbore;and analyzing the set of data to determine locations of the first andsecond proppants in formation fractures, wherein the analyzing of theset of data comprises: determining elemental yields of the first andsecond tracers; determining that the first proppant is present in theformation fractures proximate to a first set of perforations in thewellbore, and the second proppant is present in the formation fracturesproximate a second set of perforations in the wellbore when theelemental yield of the first tracer increased proximate to the first setof perforations, the elemental yield of the second tracer increasedproximate to the second set of perforations, or both.
 2. The method ofclaim 1, wherein the set of data further comprises: borehole sigma data,formation sigma data, or ratio data of count rate changes in differenttime windows after the neutron bursts, or a combination thereof.
 3. Amethod for evaluating gravel packs or frac packs in a wellbore,comprising: pumping a first proppant into the wellbore, wherein thefirst proppant comprises a first tracer comprising an element selectedfrom the group consisting of gadolinium, boron, and samarium; pumping asecond proppant into the wellbore, simultaneous with or after the firstproppant is pumped into the wellbore, wherein the second proppantcomprises a second tracer comprising a different element selected fromthe group consisting of gadolinium, boron, and samarium, and wherein thesecond tracer is different than the first tracer; obtaining a first setof data in the wellbore using a pulsed neutron logging tool after thefirst and second proppants are pumped into the wellbore; and analyzingthe first set of data to determine locations of the first and secondproppants in a gravel pack region in the wellbore, in induced formationfractures, or both.
 4. The method of claim 3, further comprising:obtaining a second set of data with the pulsed neutron logging toolprior to pumping the first and second proppants; and comparing the firstand second sets of data to determine locations of the first and secondproppants in the gravel pack region in the wellbore, in the inducedfractures in the formation, or both.
 5. The method of claim 4, whereinthe first set of data, the second set of data, the comparison of thefirst and second sets of data, or a combination thereof comprise:borehole sigma data, formation sigma data, detector count rate data indifferent time windows after neutron bursts, ratio data of count ratechanges in different time windows after the neutron bursts, elementalyield data of the first tracer, the second tracer, or both, or acombination thereof.
 6. The method of claim 5, wherein comparing thefirst and second sets of data comprises comparing detector count ratechanges between the first and second sets of data in an early timewindow after neutron bursts, wherein the early time window is from about35 μs to about 150 μs.
 7. The method of claim 6, further comprisingdetermining, based on the comparison of the detector count rate changes,that one of the first and second tracers comprises boron and is presentin first formation fractures when the detector count rate decreasesproximate to a first set of perforations adjacent to the first formationfractures.
 8. A method for evaluating induced fractures in a wellbore,comprising: obtaining a first set of data in a wellbore using a pulsedneutron logging tool; pumping a frac fluid and a proppant into thewellbore simultaneously, after the first set of data is captured,wherein the frac fluid comprises a first tracer comprising an elementselected from the group consisting of gadolinium, boron, and samarium,and wherein the proppant comprises a second tracer comprising adifferent element selected from the group consisting of gadolinium,boron, and samarium, and wherein the second tracer is different than thefirst tracer; obtaining a second set of data in the wellbore using thepulsed neutron logging tool after the frac fluid and the proppant arepumped into the wellbore; and comparing the first and second sets ofdata to determine locations of the frac fluid the said proppant.
 9. Themethod of claim 8, wherein the first set of data, the second set ofdata, the comparison of the first and second sets of data, or acombination thereof comprise: borehole sigma data, formation sigma data,detector count rate data in different time windows after neutron bursts,ratio data of count rate changes in different time windows after theneutron bursts, elemental yield data of the first tracer, the secondtracer, or both, or a combination thereof.
 10. The method of claim 9,wherein comparing the first and second sets of data comprises comparingdetector count rate changes between the first and second sets of data ina late time window after neutron bursts, wherein the late time window isfrom about 200 μs to about 1,000 μs.
 11. The method of claim 9, whereincomparing the first and second sets of data comprises computing a ratioof a detector count rate change in an early time window after neutronbursts relative to the detector count rate change in a late time windowafter the neutron bursts, wherein the early time window is from about 35μs to about 150 μs.
 12. The method of claim 11, wherein the ratio ispositive in the presence of boron, and negative in the presence ofgadolinium or samarium.